Shale Oil Fiasco

Gerry Maddoux · December 26, 2019

5 minutes ago, D Coyne said:

Dennis, I'm arguing my book here, but I think too much credit has been dished out about the all-mighty Permian and not enough to the Bakken. I realize that people consider the Bakken to be a "mature field," but sometimes there are good aspects to being mature. Indeed, on my tiny parcels up there, an independent petroleum engineer calculated that there is room for another 550 profitable wells. That makes me think there is a huge capacity up there. To show that the Bakken is already in terminal decline may not be fair to it. I mean, when you look at IP, cost of drilling, parent-child interaction, low gas/oil ratios, low water burden--everything but pipeline infrastructure--you come away shaking your head . . . at least if you're an old guy like me.

D Coyne · December 26, 2019

4 minutes ago, Gerry Maddoux said:

Dennis, I would (selfishly) argue that oil prices are not "very high," at least when measured against other commodities . . . and especially when compared to frivolous commodities that are not necessary to sustain life. I have used this so much someone will put in an emoji of gagging, but here goes. If you were to roll a new oil barrel into a Starbucks and fill it with latte, it would cost you $3700. No one has indexed oil to the stealth inflation that's all around us: cost of food, coffee, liquor, bottled water, hotel rooms, airline tickets, on and on.

Further, the production of a barrel of oil used to be a low-cost thing: drill a vertical well, let it flow. These days, every time I venture out into the oil field I am amazed at what's going on: drill bit sensors, computers massaging the data, this new e-fracking. We're not talking picking coffee beans in the sunshine; the cost of producing a barrel of LTO is staggering.

In Saudi Arabia, the cost to produce a barrel of oil is not staggering. It's about $11, maybe add on another couple of bucks for sea-water flooding. But their social cost is high. Same for a lot of other large oil pool countries.

In 1993 the price of oil was $10 and the cost of lifting WTI was $12. Nobody could make a buck. Lots of people shut in wells or just plugged them (you could do that back then for $1500). Plugging a well to Texas Railroad Commission standards now costs $30,000. At these current oil and gas prices, there are going to be quite a lot of wells that get plugged early. Enough that it's going to spur cottage industries in that field.

Gerry,

I do not mean oil prices are very high right now. The scenario I use for the model has high future oil prices ($171/bo in 2018$ for Brent crude for the maximum in 2050). See chart below. Mr Shellman will think this scenario is absurd, I certainly agree we do not know future oil prices, I would consider this an upper bound on what we might expect, if World oil output peaks in 2025 as I expect.

Old-Ruffneck · December 26, 2019

7 minutes ago, Gerry Maddoux said:

In 1993 the price of oil was $10 and the cost of lifting WTI was $12. Nobody could make a buck.

That is just not true. I may have left the WT oilfields in late 86 but they were making money. Reaganomics killed the "patch" and took 12 to 15 years to stabilize. Right now going into 2020 $58.00 LTO and WTI is a comfortable place. Get greedy and the house of cards will collapse. Just my opinion.

D Coyne · December 26, 2019

9 minutes ago, Gerry Maddoux said:

Dennis, I'm arguing my book here, but I think too much credit has been dished out about the all-mighty Permian and not enough to the Bakken. I realize that people consider the Bakken to be a "mature field," but sometimes there are good aspects to being mature. Indeed, on my tiny parcels up there, an independent petroleum engineer calculated that there is room for another 550 profitable wells. That makes me think there is a huge capacity up there. To show that the Bakken is already in terminal decline may not be fair to it. I mean, when you look at IP, cost of drilling, parent-child interaction, low gas/oil ratios, low water burden--everything but pipeline infrastructure--you come away shaking your head . . . at least if you're an old guy like me.

Gerry,

The US less permian includes all plays besides the Permian. Bakken has a lot of old wells that will decline and Permian basin may be more profitable as transport costs are lower. Model has URR of 10.2 Gb about equal to USGS TRR for ND Bakken/TF.

Gerry Maddoux · December 26, 2019

I'd say your $171 would be just about the appropriate price for a barrel of oil . . . but today, not in 2050. Don't forget, for ten years inflation has been totally beat down by Quantitive Easing, driving interest rates to almost zero in the US and below zero in many European countries. Oil prices have traditionally tracked inflation, so prices, one might say, have been kept artificially low by the Federal Reserve. If we were running the traditional 4-5% core inflation, what would the price of oil be? I say very close to $200.

How do I figure that? Naively, I can assure you! Again, to use the coffee commodity comparison, when oil was $10 back in 1993, the price of a cup of coffee was 25 cents. Using 2019 prices, a cup of latte at $5, that would put the price of oil at $200. Like I said, primitive, but realistic, too. I seriously believe that the price of a barrel of oil should be at $150-$200.

Old-Ruffneck · December 26, 2019

6 minutes ago, Gerry Maddoux said:

I'd say your $171 would be just about the appropriate price for a barrel of oil . . . but today, not in 2050. Don't forget, for ten years inflation has been totally beat down by Quantitive Easing, driving interest rates to almost zero in the US and below zero in many European countries. Oil prices have traditionally tracked inflation, so prices, one might say, have been kept artificially low by the Federal Reserve. If we were running the traditional 4-5% core inflation, what would the price of oil be? I say very close to $200.

How do I figure that? Naively, I can assure you! Again, to use the coffee commodity comparison, when oil was $10 back in 1993, the price of a cup of coffee was 25 cents. Using 2019 prices, a cup of latte at $5, that would put the price of oil at $200. Like I said, primitive, but realistic, too. I seriously believe that the price of a barrel of oil should be at $150-$200.

Inflation would quadruple and upwards, gas would be $12.00 a gallon, diesel even higher and that would force EV's even faster to the market. Shipping would cease at that price. No, I just don't see crude inflating that rapidly. Go ahead and dream of bankrupting half a world.

D Coyne · December 26, 2019

1 hour ago, Mike Shellman said:

"Spot" gas at Henry is only applicable to a limited few shale oil producers in any basin; free royalty on this gas is not subject to any processing or marketing costs and therefore has nothing whatsoever to do with current well economics are wild ass guesses about the future. Additional takeaway out of the Permian is actually causing the price of associated gas to go down, not up. Flaring is on the rise in all shale oil basins, accordingly. Gas to oil ratios. a precursor to depletion, are increasing dramatically in the Permian: https://www.bloomberg.com/news/articles/2019-12-24/permian-gas-problem-just-gets-worse-as-shale-drilling-slows-down.

Sent from planet Earth 12.26.19 @ 09:40. Is anybody out there?

Hi Mike,

If I had that data and fit a trend line on the April 2019 to Nov 2019 data doesn't it look like the slope would be positive?

What has changed since April 2019? I am talking about natural gas pipelines, wouldn't you think that less gas would be flared an/or vented with more natural gas pipeline capacity in West Texas? That would be my guess. My understanding is that a couple more natural gas pipelines will start operating between now and Dec 2021. Eventually as these operators try to lock up customers there will be less gas on the spot market and prices will go up.

Chart below has longer term West Texas/ NM Gas prices at Waha

Gerry Maddoux · December 26, 2019

8 minutes ago, Old-Ruffneck said:

That is just not true. I may have left the WT oilfields in late 86 but they were making money. Reaganomics killed the "patch" and took 12 to 15 years to stabilize. Right now going into 2020 $58.00 LTO and WTI is a comfortable place. Get greedy and the house of cards will collapse. Just my opinion.

We were making money in 1993, but that was on royalties. Maybe the big producers were making money at $10 oil in 1993 but my father-in-law, who was a pretty savvy old independent oilman, mourned the prices in '93, telling me that lifting costs were $12 while the price of oil was $10. If the big producers were making money it must have been pretty thin shavings.

Look, I respect your opinion, but I can tell you that at $58 for LTO, paying someone to take more and more NG off your hands, enlarging the spacing format, there are precious few people who are going to make money . . . unless you happen to have a refinery or a petrochemical plant, or both. Perhaps that's who you're referring to: only the majors.

You're right as rain: Reaganomics killed the oilfields in 1987. Many of the people I knew went broke. And it took an awful long time to get back. Sir, the greedy have acted already, and the House of Cards has already collapsed. If you happened to buy early and cheap, or bought sweet spots, maybe you're okay. But when you go in thinking you're going to drill a dozen child wells on a 1280 A tract and wind up with half that number, and then discover that they're so gassy you're paying someone to take away the NG, and then here comes much more decline in volume and pressure than anyone predicted even in a sour mood, you've got the recipe for collapse.

Anyone who know me would say that I'm not greedy. I read and write here as part of my lifelong learning program, and because I have an abiding lifelong interest in oil and gas. I'll be the first to admit that each person brings in his or her bias. I'm just flummoxed whenever I see the money and labor and sophistication that goes into the acquisition of a barrel of oil, that's all. When I compare it to 1987, I gasp. I don't know, when I see a company like Chevron take an $11B impairment, that gets my attention. That's a quarter of what Occidental paid for Anadarko. Maybe Chevron is making money hand over fist in the Delaware, but I see these prodigious quantities of NG that have to be disposed of at low prices or negative prices, and again, if they're making money hand over fist it's at their refineries and petchem plants--the wellhead isn't gushing out money.

Gerry Maddoux · December 26, 2019

5 minutes ago, Old-Ruffneck said:

Inflation would quadruple and upwards, gas would be $12.00 a gallon, diesel even higher and that would force EV's even faster to the market. Shipping would cease at that price. No, I just don't see crude inflating that rapidly. Go ahead and dream of bankrupting half a world.

I'm not dreaming of anything, sir, and I understand that your business involves a reasonable price for fuel. I respect that, and I abhor price gouging, for your information. I seem to think we're in a bigger bind than you do. I know from your previous several posts that you have tight friends in the oil field. Maybe you have the inside scoop. What the numbers say is that the Permian is declining in expectation for EUR and that the Delaware is gassy and getting gassier.

Frankly, if you want to keep your fuel costs down, I would look into NG-powered vehicles. I see LNG as the tail that's going to wag the dog for sometime, maybe for the rest of the lifespan of fossil fuels. Pipeline NG in America is going to remain low, as long as the dry gas fields and the LTO expansion goes on--probably until about 2025.

Please don't accuse me of dreaming of bankrupting half the world. You don't know me and you have wildly taken my remarks out of context. I'm stating the obvious: after the crash, the Federal Reserve figured the only way to avoid another Great Depression was to pump billions of dollars into the banking system. The side effect of that was to kill inflation for ten years. I suspect we'll have a rebound at some point, at least to traditional levels. When that happens, I would imagine that commodity prices will assume their traditional places as well.

D Coyne · December 26, 2019

16 minutes ago, Gerry Maddoux said:

I'd say your $171 would be just about the appropriate price for a barrel of oil . . . but today, not in 2050. Don't forget, for ten years inflation has been totally beat down by Quantitive Easing, driving interest rates to almost zero in the US and below zero in many European countries. Oil prices have traditionally tracked inflation, so prices, one might say, have been kept artificially low by the Federal Reserve. If we were running the traditional 4-5% core inflation, what would the price of oil be? I say very close to $200.

How do I figure that? Naively, I can assure you! Again, to use the coffee commodity comparison, when oil was $10 back in 1993, the price of a cup of coffee was 25 cents. Using 2019 prices, a cup of latte at $5, that would put the price of oil at $200. Like I said, primitive, but realistic, too. I seriously believe that the price of a barrel of oil should be at $150-$200.

Gerry,

I agree oil prices are likely to rise, remember the $171/bo is in 2018$. If we assume an average rate of inflation of 3% per year for the next 30 years, we get a nominal oil price of $415/bo in 2050 $, that is a pretty high price of oil. Oil might get to $140/bo, but enough demand will be destroyed at that price that it may stabilize or decrease as people switch to less expensive alternatives. I expect a peak in prices around 2030 at about $140 a plateau to about 2040, then gradually falling oil prices as demand falters. (All these prices in constant 2018 US$).

James Gautreau · December 26, 2019

I absolutely agree with you on the price of oil. Oil has been heavily subsidized since fracking started with well owners getting to deduct intangible drilling costs 90-100% the first year. This has cost the government a lot of money but has kept fuel cheap. But it has created the scenario we live in now, unprofitable drilling. How long this goes on is anybody's guess. Who cares if you get the money you invest back was the mantra when top rates were nearly 40%. Trump has dropped it down to 25%, so it's different math.

James Gautreau · December 26, 2019

I can't remember if I posted this before, but either way it's relevant. Mark Gordon makes a pretty compelling case oil is getting scarce fast.

https://www.youtube.com/watch?v=dhc6vyxVsDs&t=1s

Nobody wants to call a peak because they're scared of looking foolish. Oil companies of all ilk are trading at insane multiple. One of them CRZO I think is the ticker has a PE ratio of 1!

James Gautreau · December 26, 2019

It may be starting. At some point in time I expect large draws to replace the oil no longer coming out of the Permian, and I expect this in the next couple of months. 8 million barrel draw is big but I expect it to grow to 20 million barrels a week.

https://oilprice.com/Latest-Energy-News/World-News/Oil-Prices-Up-As-API-Reports-Massive-Crude-Draw.html

wrs · December 26, 2019

2 hours ago, Mike Shellman said:

"Spot" gas at Henry is only applicable to a limited few shale oil producers in any basin; free royalty on this gas is not subject to any processing or marketing costs and therefore has nothing whatsoever to do with current well economics are wild ass guesses about the future. Additional takeaway out of the Permian is actually causing the price of associated gas to go down, not up. Flaring is on the rise in all shale oil basins, accordingly. Gas to oil ratios. a precursor to depletion, are increasing dramatically in the Permian: https://www.bloomberg.com/news/articles/2019-12-24/permian-gas-problem-just-gets-worse-as-shale-drilling-slows-down.

Sent from planet Earth 12.26.19 @ 09:40. Is anybody out there?

Last month the price was $2.10. I suppose there are more than one destination and pay point for the gas. I am simply reporting what I see on the royalty stubs. GOR is increasing which isn't a good thing in the current market but then GOR also increases over the life of the wells so it's expected that the overall GOR in the Permian would be increasing over time.

Edited December 26, 2019 by wrs

ceo_energemsier · December 26, 2019

5 minutes ago, James Gautreau said:

It may be starting. At some point in time I expect large draws to replace the oil no longer coming out of the Permian, and I expect this in the next couple of months. 8 million barrel draw is big but I expect it to grow to 20 million barrels a week.

https://oilprice.com/Latest-Energy-News/World-News/Oil-Prices-Up-As-API-Reports-Massive-Crude-Draw.html

What oil isnt coming out of the Permian or hasnt come out of the Permian to force companies to draw down from storage in the last 2-3 weeks?

ceo_energemsier · December 26, 2019

Permian Poised To Deliver Strong Oil And Gas Production Growth

Compelling returns at $50 WTI portend bright supply picture.

By Brian Lidsky, Enverus Drillinginfo

This article focuses on the outlook for the Permian Basin, which will continue to grow beyond 2029 driven by its large aerial extent of economic drilling at oil prices of less than $50 WTI. Rig count trends, top operators, midstream buildout, merger and acquisition (M&A) activity and a topical discussion on well spacing are presented.

After supporting Permian operators to spend vast sums of money during 2016 and 2017 to buy land inventory, Wall Street shifted its scorecard on the industry from one of a discounted cash flow or net present value (NPV) approach to one predicated on demonstrating sustainable free cash flow to return to shareholders. This paradigm shift from Wall Street has been abrupt, and public E&P executives hear the message and are pivoting business strategies. Given the nature of the industry, the pivot will take some time but is well underway. This will impact the rate of growth in the Permian as less capital is put into the ground. But the basin supply dynamics remain strong. The Wall Street sentiment to E&P companies is currently negative, but industry innovation continues strong and more efficiencies are on the way. Enverus Drillinginfo is confident Permian Basin economics are strong enough to both grow production and return cash to shareholders. At some point, Wall Street sentiment is expected to shift back and support the great advances many companies are making.

Production forecast
Enverus Drillinginfo forecasts U.S. oil production to grow by 1.5 MMbbl/d in 2019 to an average of 12.3 MMbbl/d, an increase of 13% over 2018. This is moderated from the 2018 record growth of 17%, or 1.6 MMbbl/d. From 2020 to 2023, production growth will continue to moderate and increase by another 3.2 MMbbl/d (or an average 6%) to reach 15.5 MMbbl/d in 2023 (Figure 1).

FIGURE 1. US CRUDE PRODUCTION FORECAST

The Permian Basin leads U.S. oil growth and accounted for 1 MMbbl/d, or 62%, of the record 2018 growth. The Permian will continue to lead and is forecast to grow by another 0.8 MMbbl/d in 2019 to an average 4.3 MMbbl/d. By 2023, Permian production is forecast to average 5.7 MMbbl/d.

In 10 years U.S. production is expected to reach about 17.3 MMbbl/d, at which time the Permian will account for 40% (or 6.8 MMbbl/d) of U.S. production—up from its 35% share this year. Longer term, the Permian will continue to grow beyond 2029, which is forecast to underpin a flattening U.S. oil production profile.

For U.S. gas, growth also continues. Although, like oil, it is at a slower pace from recent history. From 2015 to 2019, gas production grew by 14.8 Bcf/d to reach a forecast average of 88.8 Bcf/d in 2019. Growth will slow by nearly 60% to add another 6.4 Bcf/d by 2024. The Permian and the Northeast will contribute equally to the growth at 2.2 Bcf/d during the next five years (Figure 2).

FIGURE 2. US DRY GAS PRODUCTION FORECAST

Well-level economics driving growth
This growth in U.S. oil production is driven by substantial swaths of land that are currently de-risked and economic at prices of $55 WTI or less. While the Permian accounts for much of this profitable drilling inventory, portions of virtually all other major resource plays contribute to this growth, including the Bakken and Eagle Ford.

Based on a bottoms-up methodology, Enverus Drillinginfo maintains well economics on more than 200 distinct groupings of areas predicated on well history and current cost economics. Shown in Figure 3 are breakeven economics for oil. There is a substantial inventory that is profitable based on half-cycle (driven by drill and complete costs) economics at oil prices less than $50 with a minimum return threshold of 12.5% (Figure 3). The second key takeaway from the breakeven analysis is the continuum of plays that become economic as oil prices rise. The “Plays on the Margin” noted in Figure 3 become economic at a WTI price of between $50 and $65.

FIGURE 3. CRUDE OIL BREAKEVENS

In aerial extent, the Permian’s Wolfcamp, Spraberry and Bone Spring formations lead the inventory counts of drillable economic locations. Within the Permian, the top tiers of these formations lie in the Delaware Basin with breakeven economics of less than $33/bbl. Average Delaware Basin breakevens are $39/bbl, while in the Midland Basin the northern section rivals the Delaware while the southern section remains challenged at $50 WTI (Figure 4).

Other leading areas outside of the Permian include the top areas in the Eagle Ford such as DeWitt County, Texas, and the Sugarkane area of Karnes County, Texas. The Antelope area of the Williston Basin also is leader in the race for breakeven economics.

FIGURE 4. CRUDE OIL BREAKEVEN EXAMPLE: RANGE OF VALUES BY PLAYS AND AREA TIERED FORMATIONS

Permian top operators
With its transformational $57 billion buy of Anadarko Petroleum, which closed Aug. 8, Occidental Petroleum extended its lead as the top Permian oil producer, currently accounting for more than 10% of the basin’s gross operated production and more than 50% ahead of the second largest producer, Concho Resources.

Figure 5 shows the top 15 producers in the Permian that collectively operate 57% of the oil production. Enverus Drillinginfo notes a long tail of smaller operators. Currently, there are more than 300 companies operating in the Permian that produce 100 bbl/d or more.

Noteworthy is that the share of the top 15 has remained consistent since 2017 at 57%. The collective growth rate for this group dropped from 38% in March 2017-2018 to 27% in March 2018-2019. Perhaps more striking is that over this two-year period, the top 15 grew production by a striking 76%.

Certainly, as companies get larger, they have performed admirably with growing production. Growing from a large base of production presents a complex set of business and operational issues. As time marches on, these large operators continue to find business process improvements that positively affect cost structure and consistency.

FIGURE 5. PERMIAN BASIN: TOP 15 OPERATORS CONTROL 57% OF PRODUCTION

Permian climbing as the top US region to drill
As shown in Figure 5, the top 15 operators currently account for 57% of the Permian rig count, which stands at 420 active rigs drilling for oil and gas.

Figure 6 shows the pace of drilling in the Permian in relation to the rest of the U.S. Prior to the November 2014 oil price decline, Permian rig counts peaked at 508 rigs on Oct. 27, 2014—in sync with a U.S. rig count peak of 1,543 rigs. At the time, the Permian garnered 33% of the U.S. rig count. In the early days of the downcycle, Permian rigs slumped 75% to a low of 129 rigs on April 27, 2016, and on that date took just a 30% share of the U.S. rig count.

FIGURE 6. RIG COUNT BY BASIN FROM TROUGH TO PEAK

It is in this time frame that the Permian rebirth started in earnest, driven in large part by the opening of the Delaware Basin. From that trough in April 2016, the Permian rig count consistently rose by nearly 400% over 2.5 years to reach a recent peak of 505 on Nov. 16, 2018, at which time its share of the U.S. rig count rose to 42%. It is this trough to peak rig activity that spurred the record Permian production growth in 2018, which is continuing into 2019.

Recently since its peak of 505 in November 2018, Permian rig counts have declined by about 15%, which is setting up for a slower production growth rate in 2019 and beyond. The correlation between rig counts and production, while largely directionally consistent, are not directly correlated as operators are continuously innovating and moving toward drilling longer laterals and improving drill times. Regarding drill times, thus far in 2019, average spud to release is 19 days, an improvement from an average 21 days in 2014.

Permian oil takeaway forecast
As Permian oil production was rapidly ramping, midstream operators moved in quickly to begin building additional long-haul capacity directed to the Texas Gulf Coast export markets (Figure 7).

FIGURE 7. PERMIAN CRUDE INFRASTRUCTURE

Capacity out of the Permian is expected to increase by 2.1 MMbbl/d this year. Plains All American’s Cactus II pipeline, originating in Wink, Texas, and terminating in Corpus Christi, Texas, with a 650,000-bbl/d design capacity, is complete and has begun commercial operations, with full service to Corpus Christi expected by the end of the first quarter of 2020.

The largest project, Phillips 66’s (44.2% ownership) Gray Oak pipeline, has a design capacity of 900,000 bbl/d and is expected to be in service by the end of 2019. The pipeline will serve multiple Texas Gulf Coast destinations, including Corpus Christi, where it will connect to the South Texas Gateway Terminal. This marine terminal is located at the mouth of Corpus Christi Bay and is under construction by Buckeye Partners. It will have two deepwater docks with initial storage capacity of about 7 MMbbl and up to 800,000 bbl/d of throughput capacity. In addition to the South Texas Terminal, Gray Oak also will service Phillip 66’s refinery in Sweeny, Texas, and the Houston markets.

Much of the increasing Permian crude is destined for the Texas Gulf Coast, where it is being exported to foreign markets. The importance of the export market for Permian crude cannot be overstated. Permian crude quality is from light to intermediate oil, and U.S. refineries are largely designed to process heavier crudes—a legacy issue from when the U.S. relied on imported crude for refinery input (Figure 8).

FIGURE 8. US OIL PRODUCTION AND EXPORTS

Until recently, China was the largest recipient of U.S. crude oil exports. Since July 2018, while U.S. exports continue to grow, China has decreased its U.S. crude imports substantially. The rest of the world has taken up the slack of China’s volumes with notable increases in both Korea and India.

Turning to Permian gas, associated gas production is rising rapidly as oil production ramps up. Current production of 10.5 Bcf/d exceeds the stated 8 Bcf/d of pipeline takeaway capacity (Figure 9).

FIGURE 9. PERMIAN GAS PRODUCTION VS. TAKEAWAY

This bottleneck will be partially relieved with Kinder Morgan’s 1.9-Bcf/d Gulf Coast Express, which runs from the Waha Hub to the Agua Dulce Hub area in Texas’ southern Gulf Coast. Gulf Coast Express began line pack in mid-July 2019 and is expected to be in full service by September 2019. News of the line pack dramatically moved Waha cash gas prices from essentially $0.00 to about $1.20/MMBtu.

Beyond this relief, Kinder Morgan’s next major gas pipeline, the Permian Highway, is expected to bring another 2 Bcf/d of Permian gas takeaway beginning in October 2020, which will push Permian gas takeaway to 11.9 Bcf/d. This will result in a temporary excess capacity of about 0.8 Bcf/d assuming Enverus Drillinginfo’s base forecast.

Like oil, most of this new Permian gas takeaway capacity is headed toward Corpus Christi. The ultimate destination is largely for LNG export. In broader terms, growing LNG export capacity is the relief valve for increasing U.S. gas production. From a zero starting point beginning in early 2016, LNG stated capacity has now grown to 5 Bcf/d from four facilities: Sabine Pass, Louisiana (Cheniere), Cameron, Louisiana (consortium of Sempra, Mitsui, Mitsubishi, Total and NYK Line), Cove Point, Maryland (Dominion Energy) and the latest in Corpus Christi (Cheniere).

Role of M&A in the Permian and the case for consolidation
Since 2015, the Permian has by far been the most active area in the U.S. for M&A activity and accounts for $98 billion of the $340 billion U.S. upstream M&A market. The $98 billion figure does exclude large transactions that cross multiple plays, such as Occidental’s recent $57 billion purchase of Anadarko Petroleum, the largest deal of this time frame. Also excluded is BP’s $10.5 billion buy of BHP’s U.S. shale portfolio in July 2018.

Remarkably, of the $98 billion spent for deals in the Permian since 2015, 70% of those dollars, or $69 billion, was allocated to the purchase of land. Breaking down the $69 billion spent on land inventory even further, $41 billion of that figure was spent in the Delaware Basin, $26 billion in the Midland Basin and the remaining $2 billion spread across both areas.

Figures 10a and 10b show some of the recent $300 million-plus deals in each of the Delaware and Midland basins since 2017. The background green shapes are each basin’s tiered acreage rated from high to low based on Enverus’ analysis of well-level economics.

FIGURE 10a. DELAWARE BASIN DEALS SINCE 2017 (GREATER THAN $300MM)

FIGURE 10b. MIDLAND BASIN DEALS SINCE 2017 (GREATER THAN $300 MM)

The money spent for inventory in the Delaware Basin opened the area to reach new heights. The biggest bet to date in the Delaware Basin stems from the recent battle between Occidental and Chevron for Anadarko Petroleum. This $57 billion win by Occidental solidified its production leadership position in the Permian and, according to Enverus Drillinginfo’s analysis, $14 billion of that number was paid for the Delaware Basin acreage position. The next two largest bets placed were Diamondback’s $9.2 billion buy of Energen (August 2018, $5.7 billion for land) and Exxon Mobil’s $5.6 billion buy of Yates Petroleum (November 2017, $5 billion for land).

On the Midland side of the Permian, the two largest bets were Concho Resources’ $9.5 billion buy of RSP Permian (March 2018, $7 billion for land) and Parsley Energy’s $2.8 billion buy of Double Eagle Petroleum (February 2017, $2.6 billion for land).

Chevron’s desire to expand in the Permian had its limits, as seen in its withdrawal from the Anadarko Petroleum battle, but it certainly signaled the allure of the Permian to major oil companies that for the most part have yet to make transformational moves. Certainly, BP’s entry into the Permian, Eagle Ford and Haynesville with its $10.5 billion buy of BHP’s legacy U.S. resource portfolio and Exxon Mobil’s $5.6 billion buy of Yates Petroleum were significant. But there is no doubt that the major oil companies have additional firepower and desire to expand their Permian presence.

The fact that, as shown earlier in this article, Exxon Mobil is by far the leading driller in the Permian with 52 rigs running and a 68% production growth rate between March 2018 and March 2019 speaks volumes as to major oil companies’ sights for the future. There is a strong likelihood that this theme applies to most of the other majors, certainly Chevron.

The Permian is primed for consolidation as the size of the prize is large. As the industry has demonstrated, there are many variables to achieving top-tier economic results in the Permian. Owning the best portions of the rocks ranks highest. Operational scale and consistency also matter. Blocking up acreage to drill 10,000-ft or longer laterals matters.

Majors rank among the top candidates to become consolidators in today’s markets, particularly given the growing valuation disconnect between their equity and public independent E&P names, not to mention the size of the balance sheet. In addition to public independents, there are also some large private operators that have always been attractive acquisition targets.

Innovation marching ahead
Much is being written today regarding finding optimal spacing within the Permian. As operators are now being graded on profitability (aka “achieving sustainable free cash flow”) versus value growth, the game has changed. Historically, public company operators built their companies with the goal of increasing the NPV of their assets and this, by its nature, drove growth and reinvestment into high return wells. This paradigm shift of the “scorecard” is changing company behavior and will impact development within the Permian.

As an example, Midland Basin leader Pioneer Natural Resources was on a mission to achieve 1 MMboe/d of production by 2026 via reinvestment into the company. Now Pioneer has pivoted to returning cash to shareholders in a meaningful manner while downshifting growth to the mid-teens.

The investment decision for optimal well-level returns versus optimal drainage of the reservoir impacts well-spacing decisions and is depicted in Figure 11.

FIGURE 11. WHAT IS OPTIMAL SPACING IN FREE CASH FLOW ERA?

Collectively as an industry, E&P operators are innovators. Perhaps more than anywhere else, those in the Permian Basin have proven this by virtue of the great advances made after the November 2014 oil price crash. Instead of retreating, the industry innovated.

There are many examples of well-level economics that are higher today at $55 or $60/bbl oil then when oil prices were north of $90/bbl. These advances in cost efficiencies and reservoir optimization speak volumes to the ultimate potential of the Permian Basin. And there is more to come.

In early August, when posed a question by an analyst if there were more efficiencies in drilling and completion costs to be had in the Permian, Diamondback CEO Travis Stice answered with a baseball analogy: The Midland Basin is “getting into inning six” while the Delaware Basin is in “inning three or four.” We are still learning.

But innovation and improvements require calculated risk taking. Only from trial and error, can the industry advance the ball for the benefit of all operators.

Recently, Concho Resources’ stock price got knocked down severely due to less than expected results from its Dominator spacing test project in Lea County, N.M., as the company pushed the envelope in search of optimal spacing. Located in an ideal area for the development test, operationally the company performed superbly. The project required the simultaneously use of seven rigs to drill 23 wells in some of the densest spacing the company has undertaken. The results indicated that the spacing was too tight.

To dive a bit deeper, Concho’s Dominator project in the Wolfcamp A bench in Lea County had a combined average well spacing of 230 ft versus a Lea County average of 600 ft (Figure 12). The location for this project is a top-performing area with greater than 80% IRRs based on type-curve economics at $50 oil (Figure 13). Furthermore, Concho had past success downspacing in Lea County.

FIGURE 12. DOMINATOR AREA: HIGH LIQUID CUT WITH HIGH IRRs drillinginfo

FIGURE 13. WOLFCAMP A PRODUCTIVITY VS SPACING

Southwest of Dominator, Concho had previously brought on a successful nine-well program drilled in 2018 on 545-ft horizontal spacing. Direct offset operators on the Dominator location had also further downspaced. So Dominator was a calculated test to logically push the limits of increased well density.

Despite the hit on Concho’s stock price, operators should be encouraged to continue to test the boundaries of optimal spacing. It is only through these tests that Permian operators collectively can optimize the reservoirs and maximize profits for company owners.

It is just this kind of prudent risk-taking that advances the ball for all within the Permian. Concho will be a better company for the learnings from Dominator. While Wall Street investors may react, sometimes overreact, there remains little doubt that efficiencies in the Permian continue to improve and the economics will reflect these gains.

Conclusion
The forecast for the Permian is brighter than ever. From a supply point of view, the basin will lead all other areas in the U.S. in production growth in the short, mid and long term. Enverus Drillinginfo forecasts Permian oil production growth to slow a bit in 2019 to an average 12.3 MMbbl/d with growth continuing but at a slower pace thereafter. Enverus Drillinginfo forecasts Permian oil production to reach 15.5 MMbbl/d by 2023 and 17.9 MMbbl/d by 2029. For gas, the Permian will match the Northeast for production growth, with each adding 2.2 Bcf/d in the next five years. Long-haul takeaway capacity for Permian gas remains at a shortage with this not being resolved until late 2020.

Underpinning the strong outlook for the Permian is a large swath of land that has proven half-cycle well-level economics profitable at prices well below $50 WTI.

Enverus Drillinginfo expects this bright outlook for the Permian to attract the world’s largest companies to expand their positions. Certainly Chevron’s recent bid for Anadarko Petroleum is a strong signal. Exxon Mobil is the largest driller in the basin. BP recently entered the Permian via its BHP buy. The case for consolidation remains strong underpinnned by the strong economic benefits of scale and control of blocky acreage for long laterals. These factors favor major oil and super independents to be the consolidators.

Innovation in the Permian has and will continue to thrive. The industry is testing the limits on well spacing and the learnings will lead to more accurate assessment of inventory and the timing and magnitude of investment decisions.

The recent pivot of operators to a free cash flow model will impact the pace of Permian growth as companies look to distribute cash back to shareholders as opposed to reinvesting in high rate of return projects.

On the global stage, growing Permian production is of paramount importance when evaluating supply and demand and developing an oil price outlook. The bright Permian outlook is a large factor that drives the current longer term price forecast of $55 WTI, with shocks significantly above or below this likely to prove transitory.

(All charts are courtesy of Enverus Drillinginfo)

ceo_energemsier · December 26, 2019

NGL Outlook: A Light At The End Of The Tunnel?

Macro trends show NGL production growth slowing down, allowing higher U.S. LPG exports in the year ahead.

Jesse Mercer, Enverus

There’s no sugar coating it: The U.S. LPG market is oversupplied. With nationwide propane inventories sitting just below record highs, prices at Mont Belvieu are seasonally at some of their lowest levels since 2015. But with gas plant NGL production growth slowing and LPG export capacity slated for another round of expansions next year, an easing of domestic oversupply conditions may soon be in the offing.

Enverus (formerly Drillinginfo Inc.) analyzed the causes of the slowing pace of gas plant NGL production growth as well as the midstream and downstream changes that will allow for higher U.S. exports of LPG in the year ahead. Enverus believes these trends point to a more constructive outlook for the domestic LPG market next year.

NGL

Slowdown in production growth

With oil and gas prices under pressure, E&P companies throughout the U.S. have been dialing back capex in order to focus on generating free cash flow. This trend is likely to continue into 2020. Since NGL is produced alongside crude oil and natural gas, any slowdown in drilling plans will certainly impact NGL production as well.

Approximately 30% to 35% of gross gas produced in the U.S. is associated gas, and the bulk of that associated gas is being produced in a handful of tight oil plays in the Permian, Williston, Anadarko and Denver-Julesburg basins, as well as the Eagle Ford play in southern Texas. As such, it should come as no surprise that the majority of NGL production growth in recent years has also been sourced from these locations.

The Permian Basin stands out as a major growth driver, making up nearly 40% of the expansion in total NGL production in the U.S. during the past 10 years. Superior economics are the main reason for this, with West Texas Intermediate (WTI)-equivalent half-cycle breakeven thresholds clustering in a range from the low $30s to high $40s per barrel (bbl) for the Delaware Basin and between $40 and $55 in the Midland Basin. Even as global crude prices soften due to a cooling global economic growth outlook, these low breakeven thresholds should keep upstream activity in the Permian moving forward. Although one can find a few exceptions, production economics are generally less advantageous in nearly every other tight oil play in the U.S., and rig counts have been trending downward.

This brings us to the topic of gas plant LPG production. Compared to 2017, growth was strong in 2018, clocking in at just under 250,000 bbl/d. This was roughly on par with the surge in production seen in 2015. It is worth noting that the average price of front-month WTI futures in 2018 was just under $65/bbl and touched intra-day highs of nearly $77/bbl. In short, the economics for drilling were good last year, at least until prices dropped into the low $40s in the fourth quarter. The price of WTI crude has since recovered to the mid-$50s but has struggled to gain much traction beyond that.

Thanks to the prior year’s drilling momentum, gas plant LPG production for the full year of 2019 is still expected to be up on average by 225,000 bbl/d vs. 2018. That momentum has since been spent though, leading to a slowing of production growth in the second half of the year. Total U.S. gas plant production of propane, normal butane and isobutane totaled 2.26 MMbbl/d in January 2019, up 330,000 bbl/d when compared to January 2018. In September, that annual rate of growth slipped to 139,000 bbl/d, according to preliminary data collected by Enverus.

That growth rate is likely to slow even more in the months ahead. Figure 3 shows annual average increases in U.S. gas plant production of propane, normal butane and isobutane under various price scenarios for WTI crude in 2020. Front-month WTI futures have been trading between $51/bbl and $56/bbl in October, and market bias has been mostly to the downside. Even the surprise attack on Saudi oil facilities on Sept. 14 did not leave a lasting mark on oil prices. Since then, the market has shrugged off other geopolitical events as well, such as the purported missile attack on an Iranian oil tanker and the uprising in Ecuador that temporarily shut the Trans-Ecuadorean Pipeline.

All macro indicators point to a softening oil market, and that spells slower production growth for NGL in the U.S. tight oil patch as upstream capex is crimped.

LPG export capacity additions

Given domestic LPG demand averaging 1.4 MMbbl/d, the U.S. is on track for a 2019 average surplus of just over 1.6 MMbbl/d. With domestic markets well-supplied, these surplus barrels need to find a home in the international cargo market or else they will end up getting parked in storage.

Such is the rate of U.S. production growth during the past two years that both inventories and exports are trending up. Indeed, weekly propane inventories reported by the Energy Information Administration (EIA) are close to levels not seen since the record highs set in November 2015. According to the EIA, LPG exports hit a record 1.47 MMbbl/d in June. Arguably, LPG exports would have continued at or near those levels through the summer if not for Hurricane Barry and Tropical Storm Imelda.

NGL

Vessel tracking indicates total LPG exports averaged just under 1.3 MMbbl/d from July through September, and have averaged just more than 1.4 MMbbl/d in the first three weeks of October.

The October start-up of Enterprise Products Partners’ 175,000 bbl/d Houston Ship Channel expansion project helps explain part of the recent increase in export volumes. The facility, the largest in the U.S., already boasted a nameplate capacity of 660,000 bbl/d before the expansion. Enterprise’s LPG exports averaged just under 465,000 bbl/d out of the facility in September, ticking up to 580 MMbbl/d in the first three weeks of October this year.

Targa’s Galena Park export terminal may also see a boost in its effective capacity with the recent completion of the Dock 2 rebuild. Galena Park’s capacity was just over 230,000 bbl/d at the end of September, but Targa’s management believes that it could increase by 70,000 to 100,000 bbl/d before the end of the fourth quarter.

NGL

Further expansions are planned at Enterprise, bringing online another 260,000 bbl/d of export capacity in late 2020. This would boost total capacity at the facility to just under 1.1 MMbbl/d. Targa also aims to boost export capacity at Galena Park late in the third quarter of next year, with capacity potentially reaching 500,000 bbl/d, according to recent company statements. Not to be left out, Energy Transfer plans to increase capacity at its Port Arthur export terminal by around 200,000 bbl/d in the fourth quarter of 2020. Energy Transfer also aims to expand Marcus Hook by 40,000 bbl/d around the same time.

If all these projects are finished on time next year, total U.S. LPG export capacity could exit 2020 at just over 2.6 MMbbl/d, up from nearly 1.7 MMbbl/d at the end of September. Of course, none of this would amount to a hill of beans if fractionation capacity remains as tight as it is today. That, however, is set to change next year as well; indeed, 10 projects totaling 1.35 MMbbl/d of incremental fractionation capacity are planned to come online between March and December.

With export and fractionation capacity both looking unconstrained next year, inventories should end next year in a better place than they are today.

NGL

A tighter domestic supply/demand balance

From a purely market fundamentals standpoint, the combined effect of slowing production and increased export capacity should be constructive for markets.

Indeed, a significant amount of newly constructed export and fractionation capacity could even go unused in the first year of operation if production growth stagnates. This is a recipe for a tighter Gulf Coast spot market as larger volumes move across the dock inside of committed economic tranches.

However, this potential tightening in U.S. market fundamentals should be taken with some amount of caution amid worrying signs of a global macroeconomic slowdown. If global manufacturing slips into recession, petrochemical feedstock demand may come under additional pressure. If this happens, the increase in U.S. LPG export capacity risks transferring the domestic glut to the global cargo market.

Gerry Maddoux · December 26, 2019

51 minutes ago, D Coyne said:

Gerry,

I agree oil prices are likely to rise, remember the $171/bo is in 2018$. If we assume an average rate of inflation of 3% per year for the next 30 years, we get a nominal oil price of $415/bo in 2050 $, that is a pretty high price of oil. Oil might get to $140/bo, but enough demand will be destroyed at that price that it may stabilize or decrease as people switch to less expensive alternatives. I expect a peak in prices around 2030 at about $140 a plateau to about 2040, then gradually falling oil prices as demand falters. (All these prices in constant 2018 US$).

These are all reasonable comments. I don't want to disagree just for the purpose of disagreement, as if that makes me a good debater: I'm not, and I am a conciliator by nature. Everyone assumes that these "less expensive alternatives" are going to come without an unexpected or unintended consequence, just because they're green renewables. I don't assume that. I can imagine a landscape filled with solar panels and windmills, producing enough energy to power the world, storing energy in giant batteries for a rainy and windless day.

However, I don't think for a minute that such a landscape is going to be without side-effects. Those will emerge when we're a quarter the way into the project, or maybe halfway, but they're going to emerge. Maybe they'll be nothing-burgers, but I doubt it. Energy has always been expensive and at at environmental cost. We're currently in the early stages of replacing tried and proven energy with a brave new world. That's the thrust of my posts: oil and gas are inexpensive in the grand scheme of things. To get to the next level without some pain is to ignore the lessons of civilization.

James Gautreau · December 26, 2019

10 minutes ago, ceo_energemsier said:

What oil isnt coming out of the Permian or hasnt come out of the Permian to force companies to draw down from storage in the last 2-3 weeks?

The decline rates of the last couple of years have reached the point of no return. 2018 will loose 3 mbpd of the 3.8 that was brought on. 2019 will be even worse and faster too. So some time at the end of this year or the first few months of 2020, large draws will be common and the perception that we have entered a period of scarcity will emerge.

https://srsroccoreport.com/the-u-s-shale-industry-hit-a-brick-wall-in-2019/

wrs · December 26, 2019

1 hour ago, Old-Ruffneck said:

That is just not true. I may have left the WT oilfields in late 86 but they were making money. Reaganomics killed the "patch" and took 12 to 15 years to stabilize. Right now going into 2020 $58.00 LTO and WTI is a comfortable place. Get greedy and the house of cards will collapse. Just my opinion.

It wasn't Reaganomics, it was the Tax Reform Act of 1986 that imposed passive loss limitations in MLPs. Thus, oil projects that were designed to be negative cash flow but positive capital appreciation all blew up. That dried up the source of funds for drilling worthless wells. That and the Saudis kicking production from 4mmbbl/day to 8mmbbl/day in less than a year collapsed the POO from around $40 to $15. Many doctors, lawyers and dentists lost their shirts and had to declare personal bankruptcy here in Texas. They were all writing off the passive losses in the MLPs against their practice income. However, when they couldn't write it off and then had to contribute cash because the POO dropped, they were in a double bind, it was very, very ugly.

ceo_energemsier · December 26, 2019

Shale EOR: Found Oil

Tight-rock operators are testing EOR ideas to produce more oil where they’ve already made hole. Here are some of their findings.

Nissa Darbonne

Oil and Gas Investor

Maybe give that bacteria that’s downhole some vitamins. Or pump that field gas back into the well. Soak the hole with CO₂? Soak it in water? Give it some water with a field-gas chaser?

The right recipe for unconventional-rock EOR remains elusive. But operators—from the Bakken to the Eagle Ford to the Permian Basin—are looking at all the formulae yet imaginable. They’ve started with what conventional-rock formations seem to like.

Most of it works at least a bit; some of it doesn’t work for very long. And, then, there’s the cost of this method vs. that method—and in contrast to what additional oil it nets. In addition, the math has to factor for production lost while the well is offline during treatment.

Ultimately, though, the perfect cocktail will boost wells’ EUR by a worthwhile fraction—without an operator paying for another hole at a cost of another 640 acres, 20,000 feet of pipe, dozens of frack stages, thousands of barrels (bbl) of water and hundreds of tons of sand.

Estimates are of at least 25 EOR pilots and projects in the Eagle Ford, involving at least 400 wells.

Field-gas injection, Bakken

In the Bakken, Liberty Resources LLC did a rich-gas huff-n-puff (HnP) pilot, Stomping Horse, in 2018 through this past May. It anticipates a second trial next year that will be larger.

The test involved injection in five wells of 11 in a two-section Liberty unit in McGregor Field in eastern Williams County, along the Nesson Anticline. Offset wells were monitored for whether the injected gas was leaving the targeted unit.

The gas was wellhead—primarily 60% methane, 20% ethane and 10% propane—with British thermal unit content of about 1,500.

A great deal was learned, according to Liberty’s follow-up report to the North Dakota Industrial Commission in September. Among the findings: This is going to need a lot more gas.

In the target area, Liberty operates adjacent sections except one north. That one is operated by Murex Petroleum Corp., which provided operational intel about the four wells in its unit as Liberty conducted the tests. The four Murex horizontals came online in 2010 through 2012 and have produced a combined 958,000 bbl of oil and 1.2 billion cubic feet (Bcf) of gas.

Overall, pilot results indicated a “demonstrated ability to inject gas within [an HnP] scheme, build pressure, contain gas within the Bakken/Three Forks intervals of the [unit] and recover injected gas,” said Gordon Pospisil, Liberty vice president, business development, and lead on the EOR projects.

The injected gas stayed within the Liberty unit. August 2019 production from the Murex wells averaged 43 barrels per day (bbl/d) and 121,000 cubic feet per day (cf/d), according to state files. June 2018 production, prior to the Liberty pilot, averaged 40 bbl/d and 111,000 cf/d.

Liberty injected a total of 158 MMcf in its wells; into this past August it had recovered 143 MMcf.

The scope was limited by the amount of gas produced from the unit and available for injection, Pospisil said, “which restricted the impact—the pressure build—within the depleted intervals and, thus, the magnitude of the oil response.”

Reservoir pressure in the unit had been more than 6,000 psi when the wells were completed; at the time of injection, pressure was less than 1,000 psi except for one well at about 1,100. Bubble point is approximately 2,500 psi.

The second pilot will involve injecting a larger amount of gas “and target wells with less depletion and higher initial bottomhole pressures,” Pospisil said.

The results from each of the five injection wells:

Leon 2MBH had been brought online in March of 2016 with a 24-hour IP of 428 bbl. Cumulative production through this past August was 75,842 bbl and 300 MMcf. Injected was 13.8 MMcf during 18 days in August of 2018. Pressure pre-injection was about 1,100 psi. Oil the month prior averaged 48.5 bbl/d; the month after injection, 55.6 bbl/d.

Leon 3TFH had been brought online in March of 2016 with an IP of 272 bbl/d. Cumulative through this past August was 92,564 bbl and 330 MMcf. Injected was a total of 10.8 MMcf in two sets: 12 days in July of 2018 and six days in September of 2018.

Pressure at the time was about 900 psi. Oil the month prior to the first injection was 33.4 bbl/d; during the month between injections, 43.3 bbl/d; the month after the second injection, 35 bbl/d.

Gohrick 5MBH had IPed 1,032 bbl/d in December of 2014. Cumulative through this past August was 240,507 bbl and 608 MMcf. Injected was a total of 42 MMcf in two sets in the fourth quarter of 2018: one for 11 days; the other, 33 days.

Pressure at the time of injection was less than 600 psi. Oil the full month prior to treatment was 21.4 bbl/d; the first full month after the set of injections, 45.1 bbl/d.

Gohrick 4MBH IPed 1,191 bbl/d in November of 2014. Cumulative through this past August was 229,557 bbl and 563 MMcf. Injected was a total of 75 MMcf over 29 days during this past January into May. Psi at the time was less than 1,000.

Production the full month prior to the first injection was 17.5 bbl/d; the first full month after the last injection, 17.9 bbl/d.

Gohrick 6TFH IPed 1,067 bbl/d in January of 2015. Cumulative through this past August was 141,367 bbl and 455 MMcf. Injected was 17.4 MMcf during 15 days in May. Psi at the time was 713. Production in the month prior to injection was 17.8 bbl/d; in the month after injection, 33.5 bbl/d.

All five of the wells were returned to production in August. Liberty cited several issues in the follow-up report:

The pilot-project gas supply was limited to what the unit had been producing;
The wells used were fairly depleted; static bottomhole pressure was well below MMP (minimum miscibility pressure) of about 2,450; and
The oil the wells didn’t make—while shut-in during injection—was cumulatively more than what additional oil Liberty got post-injection.

However, Liberty added, the project demonstrated:

Injection is possible and can be done as part of routine operations;
The injected gas can be contained within the Bakken and Three Forks and within the unit itself. Also, it can be recovered—for sale or for re-use in EOR;
Pressure was building, thus MMP is likely achievable with more intense injection;
A substantial amount of gas is needed to restore pressure to at least 2,450 psi in Bakken and Three Forks wells. But it would be better to start with wells with at least 2,450 psi in the first place; and
It’s probably best to inject more gas than just what the lease is producing.

Liberty’s next pilot will use a less-depleted unit, thus having a higher psi at the time of commencing injection. It expects this will reduce how much gas is needed and how long the wells will be shut in.

Bakken west to east

James Sorenson, an assistant director with North Dakota’s Energy & Environmental Research Center (EERC), and James Hamling, EERC principal engineer and oilfield operations group lead, reviewed Bakken EOR projects in 2016, reporting the findings in American Oil & Gas Reporter.

The projects ranged from CO₂ to field-gas injection to waterflood and looked at the Bakken from the play’s far western boundary to the far east.

shale

Far western Bakken, CO₂, 2009. Over in Elm Coulee Field, where the fracked, horizontal Bakken play began in 2000, three operators signed on to see what would happen if doing a CO₂ HnP in the play-maker well, Burning Tree State 36-2H, in Richland County, Mont.

The well had been brought online in May of 2000 by operator Lyco Energy Corp. with Halliburton Co. as a partner. In 2009, Continental Resources Inc., Enerplus Corp. and XTO Energy Inc. began injecting gas into it, Sorensen reported.

The EOR potential of existing wells in the five major U.S. tight-oil plays is 549 MMbbl as the low case, estimates Jacob Jin, ULTRecovery Corp. chairman and CEO.

Prior, the well was producing some 35 bbl/d. Some 45 MMcf of CO₂ was injected in 45 days; the wells were capped for 64 days to let the CO₂ soak in. Production peaked at 160 bbl/d eight days after brought back online and returned to 30 bbl/d before the month’s end.

In a few months, it wasn’t flowing at all. Put on pumpjack, the pre-injection rate of production resumed, according to Sorensen. It was a year since the well had been taken offline to start CO₂ injection.

Sorensen added that offset wells weren’t monitored for CO₂ migration off-lease; it’s also unknown whether there was CO₂ migration intra-lease.

Elm Coulee made 168 MMbbl of oil through 2016, the last year for which Montana published an annual oil and gas review. In that year, it remained the No. 1 oil-producing field in the state with 8.4 MMbbl.

Far eastern Bakken, CO₂, 2008. Meanwhile, EOG Resources Inc. did a CO₂ test on Austin 1-02H in Parshall Field, Mountrail County, N.D., beginning in late 2008, Sorensen wrote. The well had been brought online in December of 2007 and had been a part of the “east of the Nesson (Anticline)” play-opener, taking fracked horizontal success to the eastern boundary of the Williston Basin.

The different aspect of what EOG was doing east of the Nesson was its use of staged fracturing; the play-opener Burning Tree State in Montana had been openhole.

Austin 1-02H had IPed 781 bbl on Dec. 13, 2007, according to state files. Cumulative was 602,769 bbl through this past August.

Sorensen wrote that 30 MMcf of CO₂ was used in the 2008 EOR pilot, but data were not available on pre- or post-test reservoir conditions. “However, after 11 days of injection, CO₂ breakthrough was observed in offset well [Austin 2-03H] 1 mile west.” (Austin 2-03H’s cumulative through this August was 667,943 bbl.)

Meanwhile, three other wells within a mile of Austin 1-02H “did not see CO₂ breakthrough, suggesting that understanding the local natural fracture system is key to EOR planning,” Sorensen wrote.

Far eastern Bakken, waterflood, 2012. Also in Parshall Field, EOG tested waterflooding Wayzetta 4-16H in 2012, injecting 39,177 bbl of produced water that April through May and another 45,171 bbl in October through November, totaling 84,348 bbl, according to state data.

Wayzetta had IPed 667 bbl of oil in July of 2008, according to the well file. Cumulative through this past August was 499,957 bbl. Cumulative water—deducting for what was injected—through August was 89,219 bbl.

Sorensen wrote, “Again, no data on pre-test or post-test reservoir conditions are publicly available. There was no observable incremental improvement in oil production attributable to water injection.”

State data show the well made 135 bbl/d of oil in the month prior to injection. In the first full month post-treatment, it made 59 bbl/d. That improved to 83 bbl/d before the second treatment began.

When brought back on the second time, it was making 50 bbl/d. That improved to 82 bbl/d in subsequent months.

After taking the well offline for work that EOG didn’t describe in the well file, it came back on with 227 bbl/d in January of 2014. This past August, it was making 18 bbl/d.

Far eastern Bakken, water with a gas chaser, 2012-2014. Sorenson wrote of a third EOG pilot in Parshall Field. In this, 447,471 bbl were injected into Parshall 20-03H beginning in April 2012 and through February 2014.

The well had IPed 1,347 bbl in May of 2008, according to state data. Production prior to treatment was 60 bbl/d. Output when brought back online in 2014 was less.

EOG followed with field-gas injection that summer, totaling 89 MMcf, according to state data. The well came back on with 95 bbl/d.

Altogether, the well was offline for 26 months. Production this past August was 30 bbl/d.

Sorensen wrote, “No data on pre- or post-test reservoir conditions are available, and there is nothing in the well file to suggest that the testing activities were considered successful by the operator.”

He added that “changes in fluid production rates were observed in two offset wells, demonstrating that communication between wells can occur rapidly.”

Hess, Bakken

Sorensen added in his report that “it is important to keep in mind that the Bakken is an unconventional tight oil play.

“When viewed through a ‘conventional’ lens, a reservoir that is highly fractured with a tight matrix is not a good candidate for any conventional CO₂ EOR approach,” he wrote. “That is why these early [tight-rock EOR] tests should be viewed in the context of pioneering efforts and judged accordingly.

“The findings strongly suggest that a conventional [HnP] approach will not be effective in unconventional formations.”

Hess Corp. is looking at where in its Williston Basin leasehold EOR will work, Dougie McMichael, Hess director, Bakken well factory, told E&P magazine. Hess operated conventional-rock CO₂ EOR in the Permian, selling it to Occidental Petroleum Corp. for $600 million in 2017.

McMichael said that, while the Bakken “is complex with a dense rock matrix,” the formation “is variable across the basin.”

A Hess predecessor, Amerada Petroleum Corp., made the North Dakota oil discovery well, C. Iverson 1, in 1951. Hess’ name is on thousands of the state’s well files. With its large Bakken leasehold, it “can look at the characteristics of the rock across the formation to decide on where we think the application has the best chance of success,” McMichael said.

Challenges include whether the EOR effort will make enough additional oil, what injectant works best without requiring a lot of it—that is, being too costly—and how to keep it on lease.

Other tight-rock operators across U.S. shale plays are keeping their EOR intel tight—“as you can imagine for a technique that might have a competitive advantage,” McMichael added.

But, from what is public, it looks like the EOR challenges in other shales are similar to those of Bakken operators, he said.

EOG, Eagle Ford EOR

Operators tight-hole as much as they can for as long as they can. For example, when EOG deployed staged fracturing in the eastern Williston Basin, it asked the state to change the confidential-status policy to begin at IP rather than after spud.

Fracked horizontals take a long time, so the six-month-since-spud rule wasn’t fair, EOG had petitioned. The rule was changed to tight-hole results through up to six months after completion.

Over in Texas, operators have to file an H-13 form with the Railroad Commission (RRC) if wanting a 50% discount on severance taxes when an EOR project indicates “positive response.” Seven of the H-13 applications to date have been approved, according to Shale IOR LLC.

The firm has put together all publicly available data for 30 Eagle Ford EOR pilots and projects to date. Something certainly learned from EOG’s and others’ EOR pilots is to not do a “pilot” in the volatile-oil fairway, George Grinestaff, CEO, told attendees at Hart Energy’s DUG Eagle Ford conference in September.

Rather, the “piloting has already been done for you,” he said. So, instead, “you may want to go with a full project.”

If looking at “the low-API black-oil window, now we need to talk,” he said. EOR work there is too nascent. “We have to really start doing some design. But I would never say the black-oil window is a no-go because we [in the industry] always surprise ourselves with what we can do.”

Shale IOR looked at well, pad/unit and other details among the 30 EOR targets. “It’s not so easy to get, but we’ve gone through all of the [locations],” he said.

Prior to EOR, the forecast for EOG Resources Inc.'s Vincent eight-well pilot in Karnes County, Texas, was of eventual production of 1.4 MMbbl per well based on the decline at the time. Post-EOR results suggest 2.4 MMbbl.

In the Bakken, a challenge has been to get the reservoir back up to bubble point or higher, due to natural fractures. The Eagle Ford, though, “can achieve surface injection pressures up to 8,000 psi, and that’s really what you need to achieve high recovery with lease gas,” he told Investor in October.

Grinestaff estimates 2,500 Eagle Ford wells per year are approaching their economic limits. “There are areas where EOR will not be a candidate because of oil quality and/or gas availability,” he added.

Meanwhile, EOR should be anticipated when developing the leasehold, he said, but operators have minimal resources and drilling and completion “has been the name of the game.” Still, some EOR infrastructure can be installed as part of the unit’s development and “it’s not terribly expensive.”

The best time to start gas injection is at least before putting a well on pump. In the Permian, for example, where operators aren’t getting much, if anything, for their associated gas, reinjection may be worthwhile.

“One of the largest expenses in a gas-injection project is buying the gas to fill up depleted wells. Once fill-up is achieved, 90% of the gas is recycled,” he said. “But the earlier you start, the less expensive gas fill-up will be.”

Patience is essential. “It typically takes two to four years to start doing a process like this. It moves very slowly.”

Chris Barden, Shale IOR COO, said, “The bottom line is it works. It’s been proven now.” Losing the gas to neighbors’ wells, if not owning all of the offset wells, “is really the biggest risk.”

Most important is to understand the hydrocarbon-phase behavior in gas-injection EOR, Grinestaff said at DUG Eagle Ford. In the Eagle Ford pilots, “it’s really vaporizing. The gas itself is mobilizing a lot of oil, and you’re producing the well just like you would a gas-condensate well, so you really have to focus on the phase behavior.”

Start-up may cost $10 million; meanwhile, cash flow declines during refill. “If you can use your own gas and processing, the economics change. But it is a robust process.

“The oil is there, and we believe you can get a consistent, robust result—an incremental 200 bbl/d.”

Eagle Ford EOR, ConocoPhillips

Among the Eagle Ford projects Shale IOR has studied are some by ConocoPhillips, which has more than 1,200 wells in the play to date. Cumulative production is more than 375 million barrels of oil equivalent (MMboe), net, beginning in 2009.

Current projects are three gas-injection HnPs, all in the black-oil window where there is lower gas drive, Erec Isaacson, ConocoPhillips vice president, Gulf Coast business unit, said at DUG Eagle Ford.

“One of the key things we’re doing during our EOR pilots, again, is gathering data—data that we can use to advance the technology, to innovate as we’re going through our EOR processes, so we can understand what mechanisms are impacting EUR most for us in the various areas of our Eagle Ford field.”

A legacy asset, “it’s one of our crown jewels. We have [3] billion bbl yet to produce in front of us. We have thousands of wells yet to drill,” he said.

Marty Thalken, chairman and CEO of Protégé Energy III LLC, told conference attendees that the EOR projects he has seen to date involve some 400 wells. “The results have to be reported to the Texas RRC [in an H-13 positive-response certificate] if they’re getting incremental recovery.”

He pointed to EOG’s Vincent eight-well EOR pilot in Karnes County, Texas. Pre-EOR, the forecast was of eventual production of 1.4 MMbbl per well based on the decline at the time. Post-EOR results suggest 2.4 MMbbl.

He estimates Eagle Ford gas-injection EOR at $55 oil has an 80% or higher ROR; at $40 West Texas Intermediate, the IRR is more than 40%.

“Those that have reported to the Texas RRC to date remain in various stages; however, the range of incremental oil recovery they are indicating varies from about 120,000 to 520,000 bbl during between 15 and 31 months,” he said.

CO₂treatment, Permian

A longtime CO₂-in-conventional-rock operator, Oxy has EOR pilots underway in tight rock in the Midland and Delaware basins, according to an E&P report. It aims to integrate EOR at the well-development level eventually.

Permian shale production is largely due to “a solution-gas-drive recovery mechanism” and has “steep production declines and low expected ultimate recoveries,” Shunhua Liu, an Oxy reservoir engineer, reported as lead author of a paper presented at the Unconventional Resources Technology Conference (URTeC) in 2018.

Oxy team members, along with Core Laboratories NV, did a lab-level experiment on Wolfcamp core samples taken from a new well. The samples were introduced to CO₂, methane and unfiltered field-produced gas. The average sample had porosity of 7%.

In the PVT (pressure, volume, temperature) test, injection of each of the three gases demonstrated “miscibility at initial reservoir pressure conditions, but CO₂ was the most efficient solvent, with first-contact miscibility at the lowest tested pressure,” Lui reported.

The team then tested what would happen if using shale core plugs—each 1 inch in diameter and 2 inches in length—with CO₂ at reservoir conditions. These “showed favorable results, including good oil recovery and CO₂ utilization in up to seven consecutive [HnP] cycles.”

The oil changed during the cycles as well. A nuclear magnetic resonance test showed “significant oil-saturation reduction,” thus “the extraction efficiency of this process.”

The greatest oil recovery—0.25 gram—was from the first HnP cycle “as expected,” but subsequent HnP cycles collected additional oil with 0.035 gram coming “even in Cycle 6.” The oil produced from the seventh cycle wasn’t enough to measure.

“The multicycle incremental recovery—even at the small core-plug scale—suggests the significant potential for multiple HnP EOR cycles for a future [Wolfcamp] unconventional EOR project design,” Lui wrote.

The lightest oil—less than C16—was produced in the first cycle; the heavier oil came later.

EOR tests in the Bakken and Eagle Ford—using CO₂- and produced-gas injection as well as trying chemical injection—have been tried by operators. But the rock and fluid properties of these systems are different than in the Permian, Lui added.

Bio-stimulation, Permian Basin

Using two Permian wells, researchers looked into whether some—or maybe even a lot—of steep shale-well decline is because of contamination induced during completion. The test fed bacteria that are naturally occurring downhole, activating them to eat up materials clogging the induced fractures, including each of the nearly invisible grains of proppant.

The findings of the field-level, Permian shale “microbial HnP” EOR test were reported at URTeC this summer by lead author Jacob Jin, ULTRecovery Corp. chairman and CEO. Participating in the study was the University of Oklahoma.

The reasons for rapid decline and low EUR from unconventional rock are myriad, Jin wrote. But among them is contamination—such as from gellants and partially hydrolyzed polyacrylamide (HPAM) that “is the main component of slickwater.”

The group unclogged the pores by “injecting microbial nutrients to the stimulated reservoir volume (SRV) to grow the indigenous beneficial microbes to degrade the residual fracturing-fluid chemicals.” What happened was “the otherwise-blocked flow paths are reopened.”

The field tests were done in July of 2018 in a vertical and in a horizontal. The wells’ owners weren’t identified in the report.

The vertical—in the northern Midland Basin—was completed in 2015 in lower Spraberry and Wolfcamp A at about 9,000 feet with crosslinked, guar-based fluid. Its IP was about 110 bbl/d; cumulative by June of 2018 was about 13,200 bbl.

“This well pump could not run 24 hours per day due to [the] low liquid-production rate,” Jin wrote. Wellhead pressure at the time of the EOR trial, which pumped 500 bbl of vitamins for the indigenous bacteria into the hole, was about 48 psi.

Pre-treatment production was 274 bbl per month; post-treatment peak was 662 bbl per month a few months later. Average daily production in March 2019 was 113% more than in June 2018. “The project payout is about four months, and the ROR is far more than 100%,” Jin wrote.

The tested horizontal is in the northern Delaware Basin west of the Pecos River. The 4,500-foot lateral was completed with 20 stages in 2014 at about 9,900 feet in Wolfcamp A with slickwater. Initial pressure was about 7,000 psi, and IP was about 630 bbl/d.

By June of 2018, it had produced about 174,000 bbl. Wellhead pressure was some 300 psi. In this one, 500 bbl of vitamins were injected as well.

George Grinestaff, CEO of Shale IOR LLC, estimates 2,500 Eagle Ford wells per year are approaching their economic limits. Meanwhile, EOR should be anticipated when developing the leasehold.

Pre-treatment production was 138.5 bbl/d; post-treatment peak was 303 bbl/d in September 2018. In January 2019, six months after treatment, average daily production was 122% more than pre-treatment, suggesting to the research team that the bacteria were continuing to work downhole.

The additional EUR is about 25,000 bbl or about 9% from one treatment. Payout was about 2.5 months; the ROR, “far more” than 100%, Jin reported.

Overall, among the two trials, liquid production improved between 40% and 127% in 180 days, “which means the otherwise-polluted SRV was unblocked by the stimulated, beneficial microbes.”

In eight months after treatment, the vertical made 1,500 bbl more than the pre-treatment decline rate suggested it should; the horizontal, after eight months, about 12,000 bbl more.

“The incremental of EUR of the fractured vertical and horizontal wells was 2,100 bbl and 25,000 bbl, respectively,” Jin wrote. “And the EUR after the treatment is increased by [between] 9% and 12%.

“The payouts for both treatments were [in] two to four months. The ROR for both pilots is more than 100%.”

In both cases, “considering only 500 bbl [of] microbial nutrients were injected and not all the fractures were contacted by the nutrients, a larger treatment in future might incur more incremental EUR.”

As the bacteria-based tests suggest vertical-well EUR may improve by about 12% and horizontal by 9%, “the total EOR potential of the current existing wells in the five major U.S. shale oil plays is 549 MMbbl” of oil as the low case.

“If the [HnP] treatment is repeated several times, more additional oil might be recovered.”

He noted that producers are reluctant to perturb bacteria downhole, though, with concern that it could result in “souring, biocorrosion, hydrogen sulfide, plugging the reservoir, etc.”

The ULTRecovery process doesn’t contain sulfate, though, Jin wrote.

[Sidebar story]

Hess Explores For EOR Advances

In the ongoing effort to extract ever more stranded hydrocarbons from reservoirs, Hess Corp., Dow and the U.S. Department of Energy (DOE) have partnered in a joint program to fund research at the University of Wyoming (UW) into foam-assisted EOR technologies.

In August, the DOE contributed $8 million as part of a grant research and field pilot test program for which Dow, UW and Hess also contributed a combined $2 million. Researchers at UW believe foam-assisted hydrocarbon gas injection technology could help recover 3% to 5% more of the oil in place from unconventional reservoirs.

“The main driver for us is really to have the ability to recover more crude oil from unconventional reservoirs,” said Khalid Shaarawi, senior manager for Bakken technology at Hess.

“Right now, a significant portion of oil is left behind during primary depletion. So we want to find a way to get more oil out of the ground, unlocking those billions of barrels left behind.”

Shaarawi said that if an eventual test pilot for the technology is successful, it would be a “game-changer” for recovering stranded reserves.

Srini Prasad, head of reservoir engineering for Hess, said the research being conducted at UW builds upon previous efforts that initially focused on applying gas injection as an EOR process.

“What we have found is that the gas injection works in the lab,” he said. “It can extract oil, but one of the problems we have is breakthrough issues because of the natural and hydraulic fractures in the reservoir.

“That’s the reason we are embarking on this next stage of EOR where we are going to be using foam, using chemicals developed by Dow, where we test it in the lab and then field test it to be able to do a better job of enhancing the recovery than just using gas injection.”

Prasad said that field testing on Bakken EOR has been conducted on a smaller scale, but this venture will be the first large-scale pilot for Hess.

UW researcher and Wyoming excellence chair in petroleum engineering Mohammed Piri said that the knowledge gained throughout the course of the research project will be used to calibrate computational simulations to better predict field performance, assess and mitigate potential risks and ensure successful implementation in the field.

According to Hess, the EOR research will be conducted at an advanced experimental oil and gas research facility housed at the university’s High Bay Research Facility, which was established in partnership with Hess. During the past six years, Hess has contributed $25 million to UW’s College of Engineering and Applied Science to improve the understanding of complex rock-fluid interactions in plays such as the Bakken.

“Hess has a strategic collaboration with [UW] that does deliver a lot of value at Hess, and that helps us provide solutions to meet the world’s growing energy needs,” Shaarawi said. “We rely on [UW] for its groundbreaking research capabilities as well as their high-end technical services they give us.” —Brian Walzel

James Gautreau · December 26, 2019

The same thing happened in 2008. The dollar collapsed when oil starting moving upward. You could plot the dollar index and crude oil price and you'd have an X.

https://www.cnbc.com/2019/11/01/us-dollar-could-weaken-to-85-on-the-dollar-index-citi.html

Gerry Maddoux · December 26, 2019

19 minutes ago, wrs said:

It wasn't Reaganomics, it was the Tax Reform Act of 1986 that imposed passive loss limitations in MLPs.

That wasn't the whole story. Reagan removed price controls for oil and it worked. He decided to do the same thing for natural gas. It didn't work.

With the country horribly starved for natural gas, and with deep drilling about the only thing that produced large quantities of natural gas, he had originally put a floor under "deep gas." Deep was defined as anything deeper than 10,000 feet. Elk City quickly proclaimed itself as the Deep Gas Capital of the World. A well that we had interest in was 29,600 feet deep. It made the WSJ by producing 75 mcf/d, but lasted only three months. That well sold NG for about $10/tcf, which amounted to about $750,000/day. Needless to say, that well drew a lot of interest. Before long, every company was drilling for deep natural gas. The cost was about $10M per well.

Reagan's about-face was in 1986 or '87. I don't know whether it was part of the Tax Reform Act of 1986 or not, but he suddenly removed the floor under deep gas. It quickly returned to earth.

Anyway, the repercussions of all that really resounded in the oil field. The deep gas operators went broke. Parker Brothers had built a rig capable of going to 50,000 feet. Big Bertha lies today in the Elk City Oil and Gas Museum, having never been put to work. It is merely an oddity of the times.

James Gautreau · December 26, 2019

Permian oil issues getting worse. Less oil, more gas with each new well.

https://finance.yahoo.com/news/permian-gas-problem-just-getting-110000422.html

James Gautreau · December 26, 2019

The problem with the Permian is it just got gassier, and it turned in 2018. That is why those huge declines happened in 2018. The very nature of the new wells has fundamentally changed.

5dca646f25b1df1a234bd02cb863725d

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